Method for processing borehole seismic data

ABSTRACT

Seismic data recorded by subsurface seismic sensors placed in a borehole, such as an oil or gas well, are transformed via a process of upward wavefield propagation to pseudo-receivers at the surface of the earth. The seismic data thus transformed can be processed as though the data had been recorded by the pseudo-receivers at the surface rather than in the borehole where the data were actually recorded. This method accurately accounts for seismic source statics, anisotropy, and all velocity effects between the real receivers in the borehole and the pseudo-receivers at the surface of the earth.

RELATED APPLICATION

The present application is based on, and claims priority to theApplicants' U.S. Provisional Patent Application Ser. No. 60/542,568,entitled “Method for Processing Borehole Seismic Data,” filed on Feb. 6,2004.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates generally to the field of processing ofborehole seismic data. More specifically, the present inventiondiscloses a method for processing borehole seismic data into the form ofsurface seismic data so that conventional surface seismic dataprocessing methods can then be applied to form a subsurface image of theearth.

2. Statement of the Problem

The widely known and widely used art of surface seismology involvesplacing seismic sources and seismic receivers at the surface of theearth and recording seismic waves that originate at the seismic sourcepoint. As illustrated in FIG. 1, a conventional method of collectingseismic data in surface seismic operations is to place seismic sourcesand seismic receivers at the surface of the earth. Each seismic sourceis initiated and the seismic wavefield from the individual seismicsources is recorded on multiple receivers. Data recorded by geophones(also known as seismometers) at the surface of the earth can beprocessed by widely known methods (see, Yilmaz, O., Seismic DataProcessing, (Society of Exploration Geophysicists, 1987)) to obtain animage of the interior of the earth.

One of the most commonly used processing methods is called CDP (CommonDepth Point) processing. In this method, sources and receivers fromdifferent common source gathers (see FIG. 1) are sorted into commonmidpoint gathers, otherwise known as CDP (Common Depth Point) gathers,as illustrated in FIG. 2.

Reflections in a CDP gather are hyperbolic in the time-offset plane, asshown in FIG. 3, where the word “offset” is used to describe thehorizontal distance from the source to the receivers. The trace on theleft side of the gather in FIG. 3 has an offset of zero, in other wordsthe source and receiver were coincident in space at the time ofrecording. The time delay of reflections with increasing offset is dueto the increased seismic wave travel path with increased source-receiverseparation in the horizontal direction.

A mathematical operation known as Normal Moveout (NMO) can be applied tothe reflections in a CDP gather to correct reflection travel times sothat the reflection time after application of NMO is equivalent to thetravel time at zero-offset, i.e., where the source and receiver werecoincident at the surface of the earth at the time of recording. FIG. 4shows a synthetic common depth point gather in FIG. 3 after correctionfor NMO.

Having both sources and receivers at the surface of the earth isrequired for two key aspects of this reflection seismology technique towork properly. The two aspects are: (1) to first order, the spatialpoint from which a seismic reflection originates can be assumed to behalf way between the source and receiver; and (2) the shape of areflection in the time-offset plane is hyperbolic and can be predictedby the NMO equation. The assumptions of these two key aspects areviolated in proportion to the degree that reflecting interfaces in thesubsurface dip (or tilt) from flat lying. But even with steep dips, theearth can be imaged with well-developed surface seismic techniques.

A sub-field of reflection seismology is borehole seismology in whichseismic receivers are placed in one or more boreholes in the subsurfaceand source points are at the surface of the earth, as shown in FIG. 5.This type of data is generally known as Offset VSP (Vertical SeismicProfile) data, but is also alternatively known as 2D VSP or 3D VSP data.Alternatively the source can be in the borehole with receivers at thesurface of the earth. The borehole seismic source can be of any type,including data derived from using a drilling bit as the seismic source.This technique is commonly known as Reverse VSP.

There are significant advantages to recording seismic data by VSPmethods, not the least of which is increased seismic frequency contentover that which can be recorded at the surface of the earth. Therefore,the potential exists to obtain greater geologic detail from the data.The significant disadvantage however is that the symmetry of havingsource and receivers at the same elevation is lost. Thus, the commonmidpoint reflection point assumption is lost and the NMO equation doesnot apply. Further, there is not currently an analogous equation formidpoint determination and moveout correction to apply to offset VSPdata.

3. Solution to the Problem

The present invention provides a method that enables borehole seismicdata (e.g., VSP data) to be transformed into a form such that the datais as though it had been recorded with seismometers at the surface ofthe earth. After this transformation, the data can be processed asthough it had been originally recorded at the surface of the earth usingwell-developed methods of surface seismic data processing. Thetransformation is achieved by continuation of the wavefield in time to anumber of pseudo-receivers located at the surface. Wavefieldcontinuation can be achieved via multiple methods, two of which aredescribed below as alternative methods that achieve the desired goal ofthis invention.

The prior art in the general field of wavefield propagation includesscientific literature containing fundamental ideas that naturally springfrom the mathematics that describe elastic wave motion. For example,Huygens' principle provides that the position of a subsequent wavefrontmay be found by regarding each point of an earlier wavefront as a sourceof spherical secondary waves whose envelope constitutes the newwavefront. Elmore and Heald, Physics of Waves, page 323 (DoverPublications, 1969).

Specific techniques that make use of wavefield continuation in the fieldof seismic data analysis include upward continuation of surface seismicdata from the surface of the earth to relatively near-by artificialplanes for the purpose of relieving statics problems. U.S. Pat. No.5,629,905 (Lau) discloses a method for downward continuation of surfaceseismic data to arbitrary subsurface planes for the purposes of improvedimaging of complex surfaces. Specifically related to borehole seismicdata, Ala'i, Riaz, Improving Predrilling Views By Pseudo SeismicBorehole Data, Ph.D. thesis, Delft University of Technology, TheNetherlands. (1997), showed the concept of transforming surface seismicdata into zero-offset VSP seismic data by downward continuation of thesurface seismic wavefield.

None of these methods either implicitly or explicitly addresses theprocess of upward continuation of borehole seismic data for the purposeof transforming the data into a form suitable for use with surfaceseismic data processing techniques. Therefore, a need exists for amethod of processing offset VSP data that is not limited by theasymmetry imposed by the original source-receiver recording geometrythat includes the sources and receivers at very different elevations atthe time of recording.

SUMMARY OF THE INVENTION

This invention provides a method for processing seismic reflectionsrecorded with receivers in a borehole (such as an oil or gas well) withseismic sources at or near the surface of the earth in order to turn thereflection data into a seismic reflection image of the earth. Seismicdata recorded with receivers in a borehole are transformed by any meansof wavefield propagation to pseudo-receiver positions at the surface ofthe earth. For example, this wavefield propagation can be done byapplication of Huygens' principle. By this method, the observed traveltimes between source points at the surface of the earth and receivers inthe borehole are used to transform the seismic data recorded in theborehole into data traces as they would have appeared if they had beenrecorded at the surface of the earth. Application of Huygens' principlein this way accounts for all velocity variations in the earth,near-surface statics, and anisotropic velocity effects in propagation ofthe wavefield from the borehole to the surface of the earth.

Once the seismic data have been transformed to the surface of the earth,the data can be processed as normal surface seismic data. Thus the dataprocessor is able to make full use of the symmetry advantages conferredby having the seismic sources and receivers at or near the sameelevation. One principle benefit of this method is that reflections areplaced at their correct reflection position in the time domain by meansof the standard methods of migration of surface seismic data. Nostandard time-domain migration method is commonly practiced that allowsaccurate placement of reflections when they are migrated directly from aborehole (deep subsurface) position.

Application of this invention to real Offset VSP seismic data results inhigh-quality reflection images of the earth in two-way time and in thecorrect horizontal spatial dimensions. These images can be directly usedas time-domain images for interpretation.

Reciprocity principles allow this method to be applied to Reverse VSPdata just as well as it is applied to normal offset VSP data. Sourcepoints in the borehole and receivers at the surface of the earth providethe same travel time information that is required to apply Huygens'principle in creating new pseudo-receivers at the surface.

These and other advantages, features, and objects of the presentinvention will be more readily understood in view of the followingdetailed description and the drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

The present invention can be more readily understood in conjunction withthe accompanying drawings, in which:

FIG. 1 is a cross-sectional diagram of a portion of the earth's surfaceshowing a number of source-receiver pairs in a common source gather.

FIG. 2 is a cross-sectional diagram similar to FIG. 1 showing a numberof source-receiver pairs in a common mid-point gather.

FIG. 3 is a graph showing a synthetic common seismic depth point (CDP)gather with reflections that have not been corrected for normal moveout(NMO).

FIG. 4 is a graph showing the synthetic common depth point (CDP) gatherin FIG. 3 after correction for NMO.

FIG. 5 is a cross-sectional diagram showing a number of source-receiverpairs in a common source gather recorded with seismometers in aborehole.

FIG. 6 is a graph showing a synthetic VSP common source point gather.

FIG. 7 is a cross-sectional diagram similar to FIG. 5 showing upwardcontinuation of the wavefield to the surface of the earth.

FIG. 8 is a cross-sectional diagram similar to FIG. 7 showing upwardcontinuation of the wavefield to the surface of the earth by way offinite difference methods.

FIG. 9 is a flow chart of the process for upward continuing boreholeseismic data by measured, interpolated or computed travel time delays.

FIG. 10 is a surface map showing seismic source point locations for 3DVSP as circles. The well location is depicted as a diamond.

FIG. 11 is a cross-sectional diagram similar to FIG. 5 showing wavefieldcontinuation via Huygens' principle using known or computed traveltimes.

FIG. 12 is a surface map showing pseudo-receiver positions, p, for asource point, S.

FIG. 13 is a graph of a synthetic common source gather generated byfinite difference methods.

FIG. 14 is a graph of an upward continued common source gather doneusing Huygens' principle and Equation 1.

FIG. 15 is a graph of the CDP stack created by processing upwardcontinued data as surface seismic data.

FIG. 16 is a flow diagram of the process of upward continuing boreholeseismic data by finite difference methods.

FIG. 17 is a graph of a synthetic VSP common source point gathergenerated by finite difference methods.

FIG. 18 is a graph of the upward continued common source gather shown inFIG. 17 after upward continuation by finite difference methods.

FIG. 19 is a graph of the CDP stack created by processing upwardcontinued data as surface seismic data. The data were upward continuedby finite difference methods.

DETAILED DESCRIPTION OF THE INVENTION

The present method begins with seismic data recorded as in FIG. 5 inwhich seismic receivers (seismometers, hydrophones, geophones, etc) areplaced in a borehole such as an oil or gas well and seismic sources areinitiated at or near the surface of the earth. Seismic waves propagatefrom the seismic source into the earth. Seismic energy propagates to theborehole receivers whereupon the seismic receivers generate a signal inresponse to the seismic energy. The seismometer signal is then typicallytransmitted to a recording instrument at the surface of the earth andrecorded on an electronic medium such as magnetic tape, optical device,or hard disk.

Some of the propagating energy travels directly from the seismic sourceto the receivers and provides a measure of the travel time from theseismic source position to the receiver position. Other energy reflectsfrom subsurface interfaces and is also recorded at the receivers in theborehole. Other energy propagates and is recorded as converted waves andrefractions and other energy propagates away from the borehole and isnot recorded.

After the data traces are recorded on electronic media, the data areprocessed to obtain information about the earth. FIG. 6 shows a commonsource point gather from a synthetic offset VSP dataset. Importantcomponents of the wavefield in offset VSP data are shown in thissynthetic offset VSP gather. The first arrivals are the first energythat arrives at the receiver directly from the source. The time of thefirst arrival is a key element of the method described herein. The otherimportant component is the reflections that are recorded at geophones inthe borehole. The reflections are propagated to the surface of the earthvia upward continuation or application of Huygens' principle and knowntravel times from the surface of the earth to receivers in thesubsurface.

A key step in the present process is to continue the VSP wavefieldupward to the surface of the earth in order to represent the data as itwould have been recorded at the surface of the earth rather than in theborehole. FIG. 7 depicts upward continuation of the wavefield to thesurface of the earth. The dataset recorded in the borehole is thustransformed into a dataset that mimics the case in which the data hadbeen recorded at the surface of the earth. The dashed arrows depict thewavefield being continued to the surface of the earth. Aftertransformation of the data into surface seismic data, the data can beprocessed using surface seismic processing methods, including commonmid-point sorting and the NMO equation. FIG. 7 shows pseudo-receivers P₁through P_(n) at the surface of the earth. The term “pseudo-receiver” isused herein to indicate the location of a seismometer to which data waspropagated from a real receiver position in a borehole.

Upward continuation of the wavefield by Huygens' principle can also bemodeled via finite difference or finite element methods as shown in FIG.8. Finite difference propagation essentially propagates each amplituderecorded at each receiver through a velocity field to pseudo-receiversat the surface of earth. The data can then be processed as surfaceseismic data. Finite difference propagation of the wavefield iscurrently prohibitively expensive for common practice, though it doeswork and should be considered to be one possible embodiment of thepresent invention.

To use the finite difference method the data processor must provide avelocity model of the earth through which to propagate the seismicamplitudes. The extent to which the upward continued data can be usedfor successfully obtaining an image is related to the accuracy of thevelocity model. While finite difference methods can be used for upwardcontinuation of the wavefield, the following alternative method ispreferred for the following reasons: (1) the alternative method does notrequire the provision of a velocity model, but incorporates allanisotropic and statics factors in the upward continuation; and (2) thealternative method requires many orders of magnitude less computer timeto compute the upward continued seismic data than finite difference orfinite element methods.

FIG. 9 is a flow diagram of the alternative, preferred process forupward continuing borehole seismic data by measured, interpolated, orcomputed travel time delays. This method of upward continuing the datato the surface of the earth begins with picking the first arrival timesfor source points in the survey. FIG. 10 shows a 3D VSP source point mapfor a hypothetical 3D VSP survey. Seismic source locations at thesurface of the earth are depicted as filled circles. The well locationat the surface of the earth is shown as a diamond near the center of thesource points.

Borehole seismic data is initially acquired as previously described(step 61 in FIG. 9) and shown for example in FIG. 5. The travel timefrom each source point location to every receiver in the borehole can bedetermined from the first arrival times on the shot records (step 62 inFIG. 9). The travel time from a point that is not on a real source pointcan be estimated by interpolating travel times based on nearby sourcepoints. Such a dataset would constitute a 3D VSP. The first arrivaltimes are picked for as many source points as is required to accuratelyinterpolate the first arrival time for any point at the surface of theearth within the survey area where source points are present. In normalsurveys, all first arrivals are picked for each source point. The firstarrival time information is stored. The first arrival information foreach source-receiver pair must be stored in such a way that the sourcecoordinates (X, Y, and Elevation) can be associated with the firstarrival time and the specific receiver of the source-receiver pair. Forexample the data can be stored in columns as follows.

SRC_X SRC_Y SRC_EL RNUM FB_PICK 100. 200. 344. 1 221.4 100. 200. 344. 2225.6 100. 200. 344. 3 229.9 200. 350. 317. 1 188.0 200. 350. 317. 2194.1 200. 350. 317. 3 199.4Where SRC_X is the source point X-coordinate, SRC_Y is the source pointY-coordinate, SRC_EL is the source point elevation. RNUM is the receivernumber or some number that uniquely identifies each receiver in theborehole, and FB_PICK is the first break pick time. In this exampleFB_PICK would be stored in milliseconds.

The next step in the preferred method of upward continuation is toactually upward continue the data to the surface of the earth usingHuygens' principle. As was discussed above, Huygens' principle statesthat a wavefront at one time and place is the summation of a set ofvirtual source points when the wavefront was at another location atanother time. Berryhill, “Wave-Equation Datuming”, Geophysics, vol. 44,no. 8, pp. 1329-1344 (1979) noted that continuation of a wavefield fromone location to another through time could be achieved if travel timesbetween the wavefront and the point to which the wave was beingcontinued could be obtained. Berryhill's function for continuation is:

S(t)=ΣWi(t−Ti)*f(t)   (Equation 1)

Where S(t) is the seismogram as a function of time, t, at the locationto which the wavefield was propagated, Wi is the seismogram at thei^(th) location from which the wavefield was propagated, Ti is theseismic travel time for a wave between the position S and the positionWi, and f(t) is a filter that, while recommended by Berryhill, isoptional. FIG. 11 is a cross-sectional diagram illustrating wavefieldcontinuation via Huygens' principle using known or computed traveltimes. The wavefield can be continued to pseudo-receivers at the surfaceof the earth in a much faster way than finite difference upwardcontinuation. Berryhill discusses a method of fast wavefieldcontinuation by application of Huygens' principle if the seismic traveltime between a real receiver and a pseudo-receiver are known. In thecase of 3D VSP data or offset VSP data, the travel times from thesurface of the earth to the receivers in the borehole are either knownfrom direct first break pick times (as depicted by the dashed lines) orcan be computed if the observed travel times are not known. Thus thewavefield as it would have been recorded at the pseudo-receivers can bequickly and accurately approximated by summing wavefield amplitudesrecorded in the borehole after application of the time delay observed onfirst breaks, as previously described with regard to Equation 1. Werefer to the upward continued data as a “Huygens Stack”.

In particular, the present method creates pseudo-receiver positions atthe surface of the earth for each of the source points (step 63 in FIG.9). For example, FIG. 12 shows the map view of a line of pseudo-receiverpositions, p, that extend from the receiver well in a direction that isco-linear with the source, S, and the top of the well location. Thetravel times from each position, p, to the receivers in the receiverwell can be interpolated from first arrival travel times measured forsource points (filled circles) that are nearby the position of eachpoint, p. The synthetic seismogram at each location, p, is computed byEquation 1 where the time delay, Ti, which is the only unknown on theright hand side of Equation 1, is either known from measured firstarrivals at each receiver location in the borehole, or can be accuratelyinterpolated from the first arrival picks from source points thatsurround the pseudo-receiver position (step 64 in FIG. 9). The resultingsynthetic seismograms can then be processed using conventionaltechniques as if they were actual surface seismic data (step 65 in FIG.9).

The seismograms created for the pseudo-receivers at the surface of theearth have the following attributes:

-   -   a) They can be used as seismograms that were recorded at the        surface of the earth and thus standard surface seismic data        processing methods can be applied to the data.    -   b) The seismograms have all static time delays that affect the        travel time from the seismic source to the seismic receivers.        Thus, surface-consistent data processing will yield consistent        source and receiver statics.    -   c) The reflection point between the source and receiver can be        estimated based on the source-receiver position and the dip of        beds in the same way that it is done for normal surface seismic        data. This is one of the most important aspects of this        technology given that estimating the reflection point for        geophones in the borehole is a function of the unknown velocity        field and the source and receiver position. When the receiver is        near the same elevation as the source, the reflection point can        initially be assumed to be half way between the source and        receiver position and the unknown velocity field can be        determined by standard NMO analysis.        Travel times delays that are applied as the Ti term in Equation        1 are not restricted to measured first arrival travel times. The        value used in Ti can be computed from ray tracing or other        travel time estimation techniques, such as picking first breaks        from data produced from finite difference modeling.

Pseudo-receivers can be placed in arbitrary positions relative to thereal source and receiver position if the travel time term in Equation 1can be either measured or estimated. The geophysical relevance ofpseudo-receiver placement is dependent on the dataset and thegeophysical method that is being applied. The geophysical relevance ofthe receiver position is related to the direction of propagating wavesthat are recorded in the borehole. Multi-component geophones that aretypically used in modern VSP recording can be used to determine thedirection of wavefield propagation and then be applied to determiningthe optimal placement of pseudo-receivers.

Example of Upward Continuation by Travel Times. FIG. 13 shows asynthetic common source gather generated by the finite differencesoftware to demonstrate the present method. The gather in FIG. 13 is oneof a set of eleven finite difference shot records with varyinghorizontal source-receiver offsets that were computed to demonstrate themethods described. The upward continued version of this shot is shown inFIG. 14. Upward continuation was done by using Huygens' principle andEquation 1 described above. Source and receiver coordinates wereassigned to the data traces for all upward continued common sourcegathers. Common depth point numbers were assigned to the traces of thetwelve upward continued shots (not shown) via the standard method insurface seismic data processing. The data were sorted by CDP gather andnormal moveout velocities were picked and applied to the dataset. Thetwo-way time image (see FIG. 15) was then created by stacking themoveout-corrected CDPs. Travel times to the receivers were symmetric oneither side of the well because the velocity model was one-dimensionaland the receiver well was vertical.

Method Using Finite Difference Upward Continuation. For the reasonsmentioned above, upward continuation via finite difference is inferiorto upward continuation by the summing method in Equation 1. Finitedifference upward continuation methods for VSP processing have beenreduced to practice as a result of our work. In spite of itsinferiority, this invention should be understood to include the finitedifference technique as a way of upward continuation of VSP data to thesurface of the earth or to an elevation near the source elevation forthe purpose of seismic reflection imaging of borehole seismic data.

FIG. 16 is a diagram of the processes using finite difference upwardcontinuation rather than the preferred method of upward continuation viafirst arrival times. Borehole seismic data is initially acquired aspreviously described (step 161 in FIG. 16). A set of pseudo-receiverpositions are determined at the surface of the earth for each of thesource points (step 162 in FIG. 16). As in the Huygens Stack methoddescribed above, the VSP common source gathers are filtered so as toextract the upward traveling seismic waves for upward continuation. Thewavefield was then propagated through a velocity model topseudo-receivers at an elevation that was equal to the seismic dataprocessing datum elevation that was selected for processing (step 163 inFIG. 16). The elevation selected was the mean source elevation for thesurvey though any elevation can be selected and this invention shouldnot be restricted to using the mean source elevation. As in the use ofthe stack method of Equation 1, the receiver coordinates were assignedto the pseudo-receivers at the surface of the earth and the data traceswere input to a surface seismic data processing flow.

FIG. 17 shows a finite difference common source gather. FIG. 18 is theshot record after upward continuation to the elevation of the source byfinite difference methods. The trace with the smallest horizontal offsetfrom the source point is shown on the right. Increasing horizontalsource-receiver offset is to the left. FIG. 19 is the image producedafter processing the synthetic VSP data after upward continuation withfinite difference methods. As before, resulting synthetic seismogramscan be processed using conventional techniques as if they were actualsurface seismic data (step 164 in FIG. 16).

General Application of Wave Equation Approximations. Upward continuationof VSP data by the Huygens Stack method or finite difference methods areall approximations of the general wave equation. All of these methodscan be used to predict a wavefield at the surface of the earth based onseismic data that has been recorded in a borehole, which can then betreated as surface seismic data. It is possible that otherapproximations of the general wave equation could be employed for thispurpose. The present invention should be construed to include otherapproximations of the general wave equations used to predict thewavefield at the surface of the earth, so that the wavefield can betreated as surface seismic data for purposes of subsequent seismic dataprocessing.

The above disclosure sets forth a number of embodiments of the presentinvention described in detail with respect to the accompanying drawings.Those skilled in this art will appreciate that various changes,modifications, other structural arrangements, and other embodimentscould be practiced under the teachings of the present invention withoutdeparting from the scope of this invention as set forth in the followingclaims.

1-20. (canceled)
 21. A method for processing seismic data recorded froma receiver in a borehole from a first seismic source near the surface ofthe earth, the method comprising: selecting a location for apseudo-receiver adjacent to a second seismic source and propagating therecorded wavefield from the receiver to the pseudo-receiver to createtransformed seismic data based on a measured first arrival travel timebetween the second seismic source and the receiver wherein the secondseismic source is part of a 3D shot record.
 22. The method of claim 1wherein the 3D shot record includes data recorded with multi-componentgeophones.
 23. The method of claim 1 wherein propagating the wavefieldfurther comprises: determining a time delay for each of a plurality ofreceivers in the borehole, each time delay substantially equal to afirst-arrival time between the second seismic source adjacent to thepseudo-receiver and each of the plurality of receivers; applying eachdetermined time delay to seismic data associated with each of theplurality of receivers in the borehole to obtain time shifted seismicdata; and summing the time shifted seismic data to obtainpseudo-receiver associated seismic data.
 24. The method of claim 1wherein propagating the wavefield further comprises: determining apseudo-receiver associated time delay for each of a plurality ofreceivers in the borehole, each time delay determined from measuredfirst-arrival times associated with a plurality of seismic sourcesadjacent to the pseudo-receiver; applying each determined time delay tothe seismic data to obtain time shifted seismic data; and summing thetime shifted seismic data to obtain pseudo-receiver associated seismicdata.
 25. The method of claim 1 wherein propagating the recordedwavefield from the receiver to the pseudo-receiver further comprisesdetermining a time delay to apply to the seismic data recorded in theborehole by interpolation from first arrival times at the receiver froma plurality of seismic sources adjacent to the pseudo-receiver.
 26. Themethod of claim 1 wherein propagating the wavefield to thepseudo-receiver further comprises summing time shifted seismic datatraces from a plurality of receivers, the time shifts interpolated frommeasured first arrival times from a plurality of seismic sourcesadjacent to the pseudo-receiver.
 27. The method of claim 1 whereintravel time from the receiver to the pseudo-receiver is calculated byray tracing.
 28. A method for processing seismic data recorded from aplurality of receivers in a borehole from a first seismic source nearthe surface of the earth comprising: selecting a location for apseudo-receiver adjacent to a second seismic source near the surface ofthe earth, wherein the second seismic source is part of a 3D shotrecord; determining a pseudo-receiver associated time delay for each ofthe plurality of receivers in the borehole, each time delay determinedfrom measured first-arrival times associated with the second seismicsource adjacent to the pseudo-receiver; applying each determinedpseudo-receiver associated time delay to the seismic data to obtain timeshifted seismic data; and summing the time shifted seismic data toobtain pseudo-receiver associated seismic data.
 29. The method of claim8 wherein determining the pseudo-receiver associated time delay furthercomprises: interpolation of measured first arrival times at the receiverfrom a plurality of seismic sources adjacent to the pseudo-receiver. 30.The method of claim 8 wherein the travel time from the plurality ofreceivers to the pseudo-receiver is calculated using a finite differencemethod.
 31. The method of claim 8 wherein the travel time from theplurality of receivers to the pseudo-receiver is calculated by raytracing.
 32. The method of claim 8 wherein the borehole receivers aremulti-component geophones.
 33. A method for processing borehole seismicdata, the method comprising: acquiring data for a borehole seismicreceiver from a first seismic source to obtain aborehole-receiver-trace; selecting a position adjacent to a secondseismic source for a pseudo-receiver near the surface of the earthwherein the second seismic source is part of a 3D shot record; measuringa seismic travel time from the second seismic source associated with thepseudo-receiver to the borehole seismic receiver to obtain a measuredtravel time value; and upward-continuing the borehole-receiver-tracefrom the borehole seismic receiver to the pseudo-receiver based on usingthe measured travel time value to obtain pseudo-receiverborehole-receiver-trace data.
 34. The method of claim 13 furthercomprising summing a plurality of pseudo-receiverborehole-receiver-traces.
 35. The method of claim 13 further comprisingsumming a plurality of pseudo-receiver borehole-receiver-tracesassociated with the pseudo-receiver position.
 36. The method of claim 13further comprising gathering a plurality of pseudo-receiverborehole-receiver-traces associated the pseudo-receiver position toobtain a gather of pseudo-receiver borehole-receiver-traces.
 37. Themethod of claim 13 wherein upward-continuing the borehole-receiver-tracedata further comprises using one of: i) a finite difference method, ii)Huygen's Principle and iii) ray-tracing.
 38. The method of claim 13wherein obtaining the measured travel time value for theborehole-receiver-trace further comprises: interpolating first arrivaltimes between a plurality of seismic sources and the borehole seismicreceiver, wherein the plurality of seismic sources are located adjacentto the pseudo-receiver position.
 39. The method of claim 13 furthercomprising determining first arrivals from source points to the boreholeseismic receiver by picking one of: i) near-by source points, ii)ray-tracing and iii) interpolated near-by source points.
 40. The methodof claim 13 further comprising processing pseudo-receiverborehole-receiver-trace data as surface seismic data.